Inverse Emulsion Polymers as Lost Circulation Material

ABSTRACT

A sealant composition comprising an inverse emulsion polymer and methods of servicing a wellbore using the same are disclosed. In one embodiment, a method of servicing a wellbore that penetrates a subterranean formation is disclosed. The method comprises placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of the fluid in the wellbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a Divisional Application of U.S. patent application Ser. No.11/180,767, filed Jul. 13, 2005, published as Patent ApplicationPublication US 2007/0012447 A1 and entitled “Inverse Emulsion Polymersas Lost Circulation Material,” which is hereby incorporated by referenceherein in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the field of sealant compositions and morespecifically to sealant compositions comprising inverse emulsionpolymers as well as methods for using such compositions to service awellbore.

2. Background of the Invention

Natural resources such as gas, oil, and water residing in a subterraneanformation or zone are usually recovered by drilling a wellbore down tothe subterranean formation while circulating a drilling fluid in thewellbore. After terminating the circulation of the drilling fluid, astring of pipe, e.g., casing, is run in the wellbore. The drilling fluidis then usually circulated downward through the interior of the pipe andupward through the annulus, which is located between the exterior of thepipe and the walls of the wellbore. Next, primary cementing is typicallyperformed whereby a cement slurry is placed in the annulus and permittedto set into a hard mass (e.g., sheath) to thereby attach the string ofpipe to the walls of the wellbore and seal the annulus. Subsequentsecondary cementing operations may also be performed. One example of asecondary cementing operation is squeeze cementing whereby a cementslurry is employed to plug and seal off undesirable flow passages in thecement sheath and/or the casing. While a cement slurry is one type ofsealant composition used in primary and secondary cementing operations,other non-cement containing sealant compositions may also be employed.

For instance, a process known as gunk-squeeze involves placing a gunkplug in a lost circulation zone to reduce fluid loss. Gunk-squeezeinvolves mixing a clay such as bentonite with a diesel and placing themixture in the wellbore where the clay contacts water to form a sealantcomposition. Drawbacks include downhole delivery problems such as mixingthe water with the clay in the wellbore. Further drawbacks include thegunk-squeeze process typically being insufficient for vugular lossesbecause the composition has a slow reacting chemistry. Other processesinclude using particles to seal lost circulation zones. Drawbacks tosuch processes include operating costs (e.g., increased pumping costs).Further drawbacks include insufficient plugging of large lostcirculation zones.

Consequently, there is a need for an improved sealant composition.Further needs include a sealant composition that is sufficient forplugging lost circulation zones and that is easily delivered downhole.

BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS

These and other needs in the art are addressed in one embodiment by amethod of servicing a wellbore that penetrates a subterranean formation.The method comprises placing a sealant composition comprising an inverseemulsion polymer into the wellbore to reduce a loss of fluid to thesubterranean formation during placement of the fluid in the wellbore.

In another embodiment, these and other needs in the art are addressed bya sealant composition comprising an inverse emulsion polymer. Theinverse emulsion polymer comprises particles having a particle size fromabout 0.01 microns to about 30 microns.

In one embodiment, these and other needs in the art are addressed by asealant composition comprising an oil dispersed polymer comprisingparticles having an average particle size from about 0.01 microns toabout 30 microns.

The sealant composition comprising an inverse emulsion polymer overcomesproblems in the art. For instance, the sealant composition may be easilydelivered downhole. In addition, the sealant composition may reducefluid loss in large permeable zones such as a vugular fracture.

The foregoing has outlined rather broadly the features and technicaladvantages of the present invention in order that the detaileddescription of the invention that follows may be better understood.Additional features and advantages of the invention will be describedhereinafter that form the subject of the claims of the invention. Itshould be appreciated by those skilled in the art that the conceptionand the specific embodiments disclosed may be readily utilized as abasis for modifying or designing other structures for carrying out thesame purposes of the present invention. It should also be realized bythose skilled in the art that such equivalent constructions do notdepart from the spirit and scope of the invention as set forth in theappended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of theinvention, reference will now be made to the accompanying drawings inwhich:

FIG. 1 illustrates a FLEXPLUG lost circulation material profile for anextrusion rheometer run;

FIG. 2 illustrates an inverse emulsion polymer and NaCl profile for anextrusion rheometer run;

FIG. 3 illustrates an inverse emulsion polymer and sea water profile foran extrusion rheometer run;

FIG. 4 illustrates a calculated Bagley coefficient for an inverseemulsion polymer and NaCl mixture; and

FIG. 5 illustrates a calculated Bagley coefficient for an inverseemulsion polymer and NaCl mixture.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In an embodiment, a sealant composition comprises an inverse emulsionpolymer. The sealant composition is a mixture that can viscosify inwellbore zones where a fluid (e.g., drilling fluid) is being lost. Forinstance, the sealant composition may viscosify in a lost circulationzone and thereby restore circulation. The viscosified mixture can setinto a flexible, resilient and tough material, which may prevent furtherfluid losses when circulation is resumed. The inverse emulsion polymermay have similar characteristics to a liquid and therefore may besuitable for delivery downhole in a wellbore.

The sealant composition is for use in a wellbore that penetrates asubterranean formation. It is to be understood that “subterraneanformation” encompasses both areas below exposed earth and areas belowearth covered by water such as ocean or fresh water. The sealantcomposition can be used for any purpose. For instance, the sealantcomposition can be used to service the wellbore. Without limitation,servicing the wellbore includes positioning the sealant composition inthe wellbore to isolate the subterranean formation from a portion of thewellbore; to support a conduit in the wellbore; to plug a void or crackin the conduit; to plug a void or crack in a cement sheath disposed inan annulus of the wellbore; to plug an opening between the cement sheathand the conduit; to prevent the loss of aqueous or non-aqueous drillingfluids into lost circulation zones such as a void, vugular zone, orfracture; to be used as a fluid in front of cement slurry in cementingoperations; to seal an annulus between the wellbore and an expandablepipe or pipe string; and combinations thereof.

The inverse emulsion polymer includes a water-in-oil emulsion with awater swellable polymer dispersed in the emulsion. The emulsion containsa continuous phase of oil and a dispersed phase of water. The oil may beany oil that is immiscible with water and suitable for use in awellbore. Without limitation, examples of suitable oils include apetroleum oil, a natural oil, a synthetically derived oil, a mineraloil, silicone oil, or combinations thereof. In some embodiments, the oilmay be an alpha olefin, an internal olefin, an ester, a diester ofcarbonic acid, a paraffin, a kerosene oil, a diesel oil, a mineral oil,silicone oil, or combinations thereof. The water may be any suitablewater for forming the dispersed phase and for use in a wellbore. Withoutlimitation, examples of suitable waters include deionized water,municipal treated water; fresh water; sea water; naturally-occurringbrine; a chloride-based, bromide-based, or formate-based brinecontaining monovalent and/or polyvalent cations; or combinationsthereof. Examples of suitable chloride-based brines include withoutlimitation sodium chloride and calcium chloride. Further withoutlimitation, examples of suitable bromide-based brines include sodiumbromide, calcium bromide, and zinc bromide. In addition, examples offormate-based brines include without limitation sodium formate,potassium formate, and cesium formate.

The inverse emulsion polymer may contain any suitable amount of oil andwater to form an inverse emulsion suitable for dispersion of the waterswellable polymer and for placement in a wellbore. In an embodiment, theinverse emulsion polymer contains from about 10 wt. % to about 80 wt. %oil, alternatively from about 30 wt. % to about 50 wt. % oil by totalweight of the inverse emulsion polymer. In addition, the inverseemulsion polymer contains from about 0 wt. % to about 70 wt. % water,alternatively from about 30 wt. % to about 70 wt. % water by totalweight of the inverse emulsion polymer.

In some embodiments, the inverse emulsion polymer contains anemulsifier. The emulsifier may be any emulsifier suitable for holdingthe oil and water in suspension. In an embodiment, the inverse emulsionpolymer contains water-soluble and oil-soluble emulsifiers (e.g.,emulsifying agents or surfactants) to stabilize the inverse emulsionpolymer. Without limitation, examples of suitable emulsifiers includepolyvalent metal soaps, phosphate esters, fatty acids, fatty acid soaps,alkylbenzene sulfonate, or combinations thereof. The inverse emulsionpolymer may contain any amount of emulsifier suitable for holding theoil and water in suspension. In an embodiment, the inverse emulsionpolymer contains from about 1 wt. % to about 10 wt. % emulsifier,alternatively from about 1 wt. % to about 20 wt. % emulsifier by totalweight of the inverse emulsion polymer.

The inverse emulsion polymer may contain any desired amount of the waterswellable polymer effective for the intended wellbore service. In anembodiment, the inverse emulsion polymer contains from about 30 wt. % toabout 50 wt. % water swellable polymer, alternatively from about 30 wt.% to about 70 wt. % water swellable polymer, and alternatively fromabout 5 wt. % to about 100 wt. % water swellable polymer by total weightof the inverse emulsion polymer. A water swellable polymer refers to anypolymer that is capable of absorbing water and swelling, i.e.,increasing in size as it absorbs the water. In an embodiment, uponswelling of the water swellable polymer, the inverse emulsion polymerforms a paste-like mass that is effective for blocking a flow pathway ofa fluid. In some embodiments, the paste-like mass has a relatively lowpermeability to fluids used to service a wellbore such as a drillingfluid, a fracturing fluid, a cement, an acidizing fluid, an injectant,and the like, thus creating a barrier to the flow of such fluids. Apaste-like mass refers to a soft, viscous mass of solids (e.g., theswelled water swellable polymer) dispersed in a liquid (the inverseemulsion). In an alternative embodiment, the inverse emulsion forms asubstantially hard, viscous mass when mixed with mud. Withoutlimitation, examples of suitable water swellable polymers includesynthetic polymers, superabsorbers, natural polymers, or combinationsthereof. Examples of suitable synthetic polymers include crosslinkedpolyacrylamide, polyacrylate, or combinations thereof.

In an embodiment, the water swellable polymer includes superabsorbers.Superabsorbers are commonly used in absorbent products such ashorticulture products, wipe and spill control agents, wire and cablewater-blocking agents, ice shipping packs, diapers, training pants,feminine care products, and a multitude of industrial uses.Superabsorbers are swellable, crosslinked polymers that have the abilityto absorb and store many times their own weight of aqueous liquids.Superabsorbers retain the liquid that they absorb and typically do notrelease the absorbed liquid, even under pressure. Examples ofsuperabsorbers include sodium acrylate-based polymers having threedimensional, network-like molecular structures. Without being limited bytheory, the polymer chains are formed by the reaction/joining ofhundreds of thousands to millions of identical units of acrylic acidmonomers, which have been substantially neutralized with sodiumhydroxide (caustic soda). Further, without being limited by theory, thecrosslinking chemicals tie the chains together to form athree-dimensional network, which enable the superabsorbers to absorbwater or water-based solutions into the spaces in the molecular networkand thus form a gel that locks up the liquid. Additional examples ofsuitable superabsorbers include but are not limited to crosslinkedpolyacrylamide; crosslinked polyacrylate; crosslinked hydrolyzedpolyacrylonitrile; salts of carboxyalkyl starch, for example, salts ofcarboxymethyl starch; salts of carboxyalkyl cellulose, for example,salts of carboxymethyl cellulose; salts of any crosslinked carboxyalkylpolysaccharide; crosslinked copolymers of acrylamide and acrylatemonomers; starch grafted with acrylonitrile and acrylate monomers;crosslinked polymers of two or more of allylsulfonate,2-acrylamido-2-methyl-1-propanesulfonic acid,3-allyloxy-2-hydroxy-1-propane-sulfonic acid, acrylamide, and acrylicacid monomers; or combinations thereof. In an embodiment, the waterswellable polymer comprises a crosslinked polyacrylamide and/orpolyacrylate. In one embodiment, the superabsorber absorbs not only manytimes its weight of water but also increases in volume upon absorptionof water many times the volume of the dry material. In an embodiment,the superabsorber increases from about 10 to about 800 times itsoriginal weight.

In an embodiment, the water swellable polymer has a particle size (i.e.,diameter) from about 0.01 microns to about 30 microns, alternativelyfrom about 1 micron to about 3 microns, before it absorbs water (i.e.,in its solid form). The swell time of the water swellable polymer may bein a range from about 5 seconds to about 5 hours, alternatively fromabout 1 second to about 48 hours.

Without being limited by theory, the micron size of the water swellablepolymer allows the inverse emulsion polymer to behave as a liquid (e.g,has similar flow characteristics to a liquid) that is sufficient fordelivery downhole in a wellbore. Further, without being limited bytheory, the micron size also allows a dehydrated form of the inverseemulsion polymer (e.g., the oil dispersed polymer) to behave as aliquid. The inverse emulsion polymer has a density from about 1.1 g/mlto about 1.7 g/ml, alternatively from about 1.0 g/ml to about 2.5 g/ml.In addition, the inverse emulsion polymer has an absorption capacityfrom about 10 to about 100 times of its own weight, alternatively fromabout 1 to about 1,000 times of its own weight.

A suitable commercial example of the inverse emulsion polymer is AE 200polymer, which is available from Hychem, Inc. AE 200 polymer containsabout 30 wt. % water swellable polymers, about 30 wt. % mineral oil,about 30 wt. % water, and about 10 wt. % emulsifier. The water swellablepolymer is comprised of about 30 wt. % polyacrylic acid and about 70 wt.% polyacrylamide cross linked polymers. The particle size of the waterswellable polymer is about 1 to about 3 microns. The inverse emulsionpolymer may have a pH of from about 5.0 to about 8.0, preferably fromabout 6.0 to about 7.5. The inverse emulsion polymer may have a densityof from about 1.0 g/ml to about 2.5 g/ml, preferably from about 1.1 g/mlto about 1.7 g/ml.

In an embodiment, a dehydrated inverse emulsion polymer is placed in thewellbore. The inverse emulsion polymer is suitably dehydrated to removeat least a portion of the water and provide an oil dispersed polymer. Inan embodiment, the inverse emulsion polymer is dehydrated to form an oildispersed polymer comprising from about 0 wt. % to about 10 wt. % water,alternatively from about 0 wt. % to about 5 wt. % water, andalternatively from about 3 wt. % to about 5 wt. % water. Without beinglimited by theory, the inverse emulsion polymer is dehydrated becausedehydration provides a higher percentage of the water swellable polymerin the polymer. Further, without being limited by theory, the inverseemulsion polymer is dehydrated to reduce the possibility ofsubstantially changing the original oil-based drilling fluid properties.The inverse emulsion polymer may be dehydrated to provide the oildispersed polymer by any suitable method. In an embodiment, the oildispersed polymer comprises from about 45 wt. % to about 50 wt. % oil,alternatively from about 30 wt. % to about 70 wt. % oil by total weightof the oil dispersed polymer. In addition, the oil dispersed polymercomprises from about 45 wt. % to about 50 wt. % water swellable polymer,alternatively from about 30 to about 70 wt. % water swellable polymer bytotal weight of the oil dispersed polymer.

The oil dispersed polymer has a density from about 1.2 g/ml to about 1.7g/ml, alternatively from about 1.0 g/ml to about 2.5 g/ml. In addition,the oil dispersed polymer has an absorption capacity from about 10 toabout 200 times of its own weight, alternatively from about 1 to about1,000 times of its own weight.

Without limitation, a commercial example of a dehydrated inverseemulsion polymer (e.g., oil dispersed polymer) is AD 200 polymer, whichis available from Hychem, Inc. AD 200 polymer is a crosslinked polymerthat contains about 1-3 wt. % water and about 50 wt. % activecomponents, which includes water swellable polymers in an amount ofabout 30 wt. % polyacrylate and about 70 wt. % polyacrylamide by totalweight of the polymer. AD 200 polymer has a density of 1.25 g/ml (±10%).In addition, AD 200 polymer has an absorption capacity (in distilledwater) of 20 g distilled water/1 g AD 200 polymer and further has anabsorption capacity (in 3% NaCl solution) of 5 g 3% NaCl solution/1 g AD200 polymer. AD 200 polymer also has a percent of non volatile residuesat 150° C. for 16 hours at 63% (±10%).

In some embodiments, the sealant composition includes additives that maybe suitable for improving or changing its properties. Withoutlimitation, examples of suitable additives include particulatematerials, viscosifying agents, weighting materials, or combinationsthereof. The weighting materials may be used to increase the density ofthe sealant composition. In one embodiment, a sufficient amount ofweighting material is mixed with the sealant composition to increase thedensity of the composition at which it passes down through the wellbore.Without being limited by theory, the increased density may increase therate at which the sealant composition passes down through the fluid inthe wellbore. Further, without being limited by theory, the density isincreased to reduce the possibility of a wellbore blow out. Withoutlimitation, examples of suitable weighting materials include barite,silica flour, zeolites, lead pellets, sand, fibers, polymeric material,or combinations thereof. The density may increase to any desireddensity. In one embodiment, the density is increased to a density fromabout 10 ppg to about 20 ppg.

In one embodiment, the inverse emulsion polymer is introduced to thewellbore to prevent the loss of aqueous or non-aqueous drilling fluidsinto lost circulation zones such as voids, vugular zones, and natural orinduced fractures while drilling. During the wellbore treatment, variouscomponents may be pumped sequentially down the workstring and/orsimultaneous down the annulus as appropriate for a given treatment. Inan embodiment, the inverse emulsion polymer is pumped in the wellbore toservice the wellbore. Before the inverse emulsion polymer is pumped intothe wellbore, a spacer fluid may be pumped into the wellbore. In someembodiments, the spacer fluid is suitable for removing water (i.e., fromthe pipes). For instance, the spacer fluid may contain a wetting agentsuch as LE SUPERMUL emulsifier. LE SUPERMUL emulsifier is commerciallyavailable from Halliburton Energy Services, Inc. The inverse emulsionpolymer is then pumped into the wellbore. In some embodiments, weightingmaterial such as barite is added to the inverse emulsion polymer priorto pumping the inverse emulsion polymer into the wellbore. After suchpumping, additional spacer fluid may be pumped into the wellbore. Thesealant composition is formed and provides a relatively viscous massinside the lost circulation zone. Drilling fluid may then be pumped intothe wellbore under suitable pressure to squeeze the sealant compositioninto the lost circulation zone. The sealant composition can also form anon-flowing, intact mass inside the lost circulation zone. This massplugs the zone and inhibits loss of subsequently pumped drilling fluid,which allows for further drilling. In an embodiment wherein the drillingfluid is non-aqueous, a treating composition may be pumped into thewellbore after the inverse emulsion polymer and additional spacer arepumped. In an embodiment, a sufficient amount of the treatingcomposition may be pumped to reduce the amounts of calcium and magnesiumin the drilling fluid in contact with the inverse emulsion polymer. Inan embodiment, the treating composition comprises soda ash, NaHCO₃, amonovalent salt, a divalent salt, or combinations thereof. Withoutlimitation, examples of such salts include Na⁺, K⁺, Ca²⁺ and Ma²⁺.Without being limited by theory, the calcium and magnesium are reducedto prevent salt poisoning in the inverse emulsion polymer or oildispersed polymer, which may prevent the formation of the desired solidpaste to plug the void in the formation. In such an embodiment, a spacerfluid may then be pumped into the wellbore followed by the drillingfluid. It is to be understood that non-aqueous drilling fluids mayinclude a diesel, a mineral oil, an internal olefin, a linearalpha-olefin, an ester, or combinations thereof. In alternativeembodiments, no spacer fluid is pumped into the wellbore before and/orafter the inverse emulsion polymer is pumped into the wellbore. In someembodiments, the inverse emulsion polymer is dehydrated to form the oildispersed polymer, and the sealant composition is formed therefrom.

In one embodiment, the sealant composition is placed in the wellborewith a water-based mud. The method for placement includes pumping atreated and active drilling mud into the wellbore. Any suitable amountof the drilling mud may be pumped into the wellbore. For instance, anamount of drilling mud comprising from about 15 to about 20 barrels maybe pumped into the wellbore. In an instance in which soluble calcium ispresent in the mud, the mud may be treated with a treating compositionto treat out at least a portion of the calcium. In an embodiment, themud is treated when the calcium is present in an amount greater than 200mg/l. Any suitable amount of the treating composition may be used. Aspacer (e.g., LE SUPERMUL emulsifier) is pumped into the wellborefollowing the mud. Any suitable amount of spacer may be pumped into thewellbore. For instance, an amount of spacer comprising from about 5barrels to about 10 barrels may be pumped into the wellbore,alternatively from about 6 barrels to about 7 barrels may be pumped intothe wellbore. The inverse emulsion polymer is pumped into the wellborefollowing the spacer. An amount of the inverse emulsion polymercomprising from about 15 to about 20 barrels, alternatively from about16 to about 17 barrels may be pumped into the wellbore. The inverseemulsion polymer may be weighted with a weighting material. An amount ofspacer is then pumped into the wellbore. The amount of spacer mayinclude from about 5 barrels to about 10 barrels, alternatively fromabout 6 barrels to about 7 barrels is pumped into the wellbore. Asuitable amount of the mud is then pumped into the wellbore. In anembodiment, the amount of mud is 20 barrels or less. After the mud ispumped into the wellbore, a light squeeze pressure is maintained for asuitable time for the sealant composition to form the non-flowing,intact mass inside the lost circulation zone. Any suitable pressure ismaintained. For instance, the pressure may be from about 175 to about225 psi. It is to be understood that in some embodiments an oildispersed polymer is placed in the wellbore with the water-based mudinstead of the inverse emulsion polymer.

In another embodiment, the sealant composition is placed in the wellborewith a non-aqueous mud. The method for placement includes pumping aspacer into the wellbore. Any suitable amount of spacer may be used. Forinstance, about 1 barrel of spacer may be pumped in the wellbore. Theinverse emulsion polymer is pumped into the wellbore following thespacer. An amount of the inverse emulsion polymer comprising from about10 to about 20 barrels, alternatively from about 16 to about 17 barrels,and alternatively about 11 barrels may be pumped into the wellbore. Theinverse emulsion polymer may be weighted with a weighting material. Anamount of spacer is pumped into the wellbore following the inverseemulsion polymer. In one embodiment, an amount of the spacer comprisingfrom about 1 to about 5 barrels, alternatively from 3 to about 5barrels, and alternatively about 2 barrels is pumped into the wellbore.A treating composition (e.g., soda ash) is pumped into the wellborefollowing the spacer. For instance, soda ash may be mixed with a spacer,drilling mud, or AD 200 polymer and pumped into the wellbore. Anysuitable amount of the treating composition may be pumped to preventsalt poisoning of the inverse emulsion polymer. In some embodiments,from about 30 to about 70 barrels of the treating composition,alternatively from about 35 to about 40 barrels, and alternatively fromabout 50 to about 70 barrels are pumped into the wellbore. An amount ofspacer fluid is pumped into the wellbore following the treatingcomposition. In one embodiment, an amount of the spacer from about 1 toabout 5 barrels is pumped into the wellbore, alternatively from about 3to about 5 barrels, and alternatively about 3.5 barrels. A suitableamount of the mud is pumped into the wellbore following the spacer. Inan embodiment, the amount of mud is 20 barrels or less. After the mud ispumped into the wellbore, a light squeeze pressure is maintained for asuitable time for the sealant composition to form the non-flowing,intact mass inside the lost circulation zone. Any suitable pressure ismaintained. For instance, the pressure may be from about 175 to about225 psi. It is to be understood that in some embodiments an oildispersed polymer is placed in the wellbore with the nonaqueous mudinstead of the inverse emulsion polymer.

In an embodiment, sealant compositions that include an inverse emulsionpolymer may be employed in well completion operations such as primaryand secondary cementing operations. In one embodiment, a spacer fluid ispumped through the drill pipe. The inverse emulsion polymer is thenpumped through the drill pipe and forms the sealant composition. Anadditional amount of spacer fluid may then be pumped through the drillpipe. In alternative embodiments, no spacer fluid is pumped into thedrill pipe before and/or after the inverse emulsion polymer. In primarycementing, such a sealant composition may be placed into an annulus ofthe wellbore and allowed to set such that it isolates the subterraneanformation from a different portion of the wellbore. The sealantcomposition thus forms a barrier that prevents fluids in thatsubterranean formation from migrating into other subterraneanformations. Within the annulus, the sealant composition also serves tosupport a conduit, e.g., casing, in the wellbore. In one embodiment, thewellbore in which the sealant composition is positioned belongs to amultilateral wellbore configuration. It is to be understood that amultilateral wellbore configuration includes at least two principalwellbores connected by one or more ancillary wellbores. In secondarycementing (often referred to as squeeze cementing), the sealantcomposition may be strategically positioned in the wellbore to plug avoid or crack in the conduit, to plug a void or crack in the hardenedsealant (e.g., cement sheath) residing in the annulus, to plug arelatively small opening known as a microannulus between the hardenedsealant and the conduit, and so forth. In some embodiments, the inverseemulsion polymer is dehydrated to form the oil dispersed polymer, andthe sealant composition is formed therefrom. Various procedures that maybe followed to use the sealant composition in a wellbore are describedin U.S. Pat. Nos. 5,346,012 and 5,588,488, which are incorporated byreference herein in their entirety.

To further illustrate various illustrative embodiments of the presentinvention, the following examples are provided.

Example 1

In this Example 1, Runs were conducted (Runs 1-9) comparing aconventional lost circulation material, FLEXPLUG lost circulationmaterial (Run 1), to an inverse emulsion polymer, AE 200 polymer (Runs2-9). FLEXPLUG lost circulation material uses particles to prevent fluidloss and is commercially available from Halliburton Energy Services,Inc. Different ratios of AE 200 polymer were mixed with deionized water,a 1% NaCl solution, or sea water. An extrusion rheometer was used totest each mixture.

The main components of the extrusion rheometer consisted of a core,which had a slit with an opening of 1 mm, 2 mm or 3 mm in width. Therheometer was 2, 4 or 6 inches long. For each Run, the rheometer wasfilled with the material (AE 200 polymer or FLEXPLUG material) to betested. A pressure was applied to push the material out of the differentsizes of cores. It was observed that different forces were needed topush different materials out of the same core under the same conditions.Such force was measured in pounds and recorded. The results are listedbelow in Table I, wherein the samples are identified by length of therheometer in inches by the width of the rheometer in millimeters (e.g.,2 mL by 1 mm W=2INLX1MMW).

TABLE I AE 200 AE 200 AE 200 AE 200 polymer:DI polymer:1% polymer:1%polymer:Sea FLEXPLUG Water NaCl NaCl Water Sample ID Material (1:9)(1:6) (1:3) (1:3) 2INLX1MMW N/A N/A N/A Ave: 209 N/A SD: 2.38 COV: 1.1%4INLX1MMW N/A Ave: 134.7 Ave: 136.3 Ave: 283 Ave: 248 SD: 5.67 SD: 5.7SD: 1.15 SD: 1.16 COV: 4.2% COV: 4.2% COV: 0.5% COV: 0.5% 6INLX1MMW N/AN/A N/A Ave: 517 N/A SD: 6.56 COV: 1.3% 2INLX2MMW N/A Ave: 46.1 Ave:41.3 Ave: 90.6 Ave: 82.0 SD: 2.61 SD: 3.27 SD: 1.88 SD: 1.76 COV: 5.7%COV: 7.9% COV: 2.1% COV: 2.1% 4INLX2MMW N/A N/A N/A Ave: 166.8 N/A SD:2.15 COV: 1.3% 6INLX2MMW N/A N/A N/A Ave: 231 N/A SD: 4.85 COV: 2.1%2INLX3MMW N/A N/A N/A Ave: 52.6 N/A SD: 3.01 COV: 5.7% 4INLX3MMW N/A N/AN/A Ave: 80.9 N/A SD: 1.87 COV: 2.3% 6INLX3MMW Ave: 526 Ave: 57.2 Ave:62.1 Ave: 114.4 Ave: 108.8 SD: 69 SD: 8.9 SD: 1.19 SD: 8.34 SD: 7.82COV: 13.1% COV: 15.6% COV: 1.9% COV: 7.3% COV: 7.2%

In the Table I, the rheometer readings are listed in pounds. The listednumber is an average of the recorded results for each Run. “SD”represents standard deviation, and “COV” represents the coefficient ofvariance, and is calculated by SD/X_(Ave).

From Table I, it can be seen that the standard deviation and COV for theAE 200 inverse emulsion polymer was much better than the FLEXPLUGmaterial. In various embodiments, rheometer readings for the inverseemulsion polymer have a SD of less than 9, 8, 7, 6, 5, 4, 3, or 2 and aCOV of less than 8%, 7%, 6%, 5%, 4%, 3%, or 2%.

FIG. 1 shows the FLEXPLUG material profile for its initial pressure,which is the initial pressure required to push the FLEXPLUG materialinto the vugular, cavernous formations. From FIG. 1, it can be seen thatthe FLEXPLUG material exhibits pressure drops. As shown in FIGS. 2 and3, there were no such pressure drops for the AE 200 polymer sample.FIGS. 1-3 show position in inches on the x-axis and load in pounds-forceon the y-axis.

Example 2

The extrusion rheometer data from EXAMPLE 1 was used in EXAMPLE 2 toderive Bagley factors for each Run. In order to derive the Bagleyfactor, the width of the slit remained the same. The different forceswere obtained by changing the lengths of the core under the sameconditions as illustrated in FIG. 4.

The Bagley factor is defined as: Bagley factor=F₀/F_(L2). F₀ is definedas the force when X=0. F_(L2) is defined as the force obtained using the4 inch core in this particular case. In general, the Bagley factor isbetween 0 and 80%. For FLEXPLUG material, the Bagley coefficient isgenerally between 25 and 80% and more typically between 35 and 55%. Thesmaller the Bagley factor, the easier the material is to be replaced bypressure or other materials.

FIGS. 4 and 5 illustrate calculated Bagley factors for different coresof AE 200 polymer:1% NaCl (1:3). From FIGS. 4 and 5, it can be seen thatthe Bagley factors are lower than such for FLEXPLUG material. By havingsuch lower Bagley factors, the AE 200 polymer and 1% NaCl mixture may bemore easily pushed into the fracture formations than the FLEXPLUGmaterial.

Example 3

AE 200 polymer was tested with a water based mud (lignosulfonate mud).Table II shows how the mud was formulated. AQUAGEL viscosifier is aviscosity and gelling agent that is commercially available fromHalliburton Energy Services, Inc. QUIK-THIN thinner is a ferrochromelignosulfonate that is commercially available from Halliburton EnergyServices, Inc. CARBONOX filtration control agent is a lignite materialthat is commercially available from Halliburton Energy Services, Inc.REV-DUST additive is a calcium montmorillonite clay that is commerciallyavailable from Milwhite, Inc.

TABLE II Lignosulfonate Mud Formulation. Sample, (lb/gal) 14.0 Freshwater, bbl 0.76 AQUAGEL 20 viscosifier, lb/bbl QUIK-THIN thinner, 6lb/bbl NaOH, lb/bbl 3 (pH ~11-11.5) CARBONOX agent, 4 lb/bbl REV-DUSTadditive, 30.0 lb/bbl Barite, lb/bbl 271.6

After hot roll in a 150° F. oven for 16 hrs, different concentrations ofAE 200 polymer in the mud were tested with the results shown in TablesIII and IV. The concentrations were tested by adding 1.0 mL of AE 200polymer and different amounts of lignosulfonate mud (e.g., as requiredby the experiment such as 1×, 2× or 50×) to a beaker. The mixture wasmixed well. The time needed for the mixture to harden and the conditionsof the mixture were recorded.

TABLE III Test Results of AE 200 polymer with Lignosulfonate Mud Sample1:1(v/v) 1:2 1:10 1:20 1:30 1:50 AE 200 Thicken Thicken Thicken Thickenwithin Slightly Slurry polymer with within 1 within 1 within 1 1 min.Forms slurry, and Lignosulfonate min. Forms min. Forms min. Forms claylike solids. more watery Mud (with loose clay like clay like Slightlywetter cement Fresh Water) solids solids solids than 1:10 like

TABLE IV Test Results of AE 200 polymer with Lignosulfonate Mud Sample1:5 (v/v) 1:10 1:15 1:20 AE 200 polymer Thicken within Thicken Slurry atfirst, Slurry at first, with Lignosulfonate 1 min. Forms within 1 min.then harden after then harden after Mud (with Sea rubbery clay Formsclay 1 hr 1.5 hr Water) like solids

As can be seen from Tables III and IV, even with the dilution factor of1:30 (AE 200 polymer:mud), the solid forms from the mixture of the twoare still cement-like slurry paste. It can be further seen from suchTables that the dilution factor decreases to 10 instead of 20 when usingthe sea water version of the lignosulfonate mud. The cations in the seawater (e.g., Na⁺, K⁺, Ca²⁺, Me⁺ and etc.) may be affecting theperformance of AE 200 polymer by salt poisoning. In this case, the saltpoisoning effect was observed to be more serious for Ca²⁺ than Na⁺. Totreat out the Ca²⁺ ions, 0.2 lb/bbl of soda ash (Na₂CO₃) was added tothe mud with excellent results. It was observed that the dilution factorincreased back to 20, and the texture of the solid was also more likethe fresh water mud.

Example 4

In EXAMPLE 4, the salinity, pH and density effects on the performance ofAE 200 polymer was observed. Different salinity, pH and density mudswere formulated as shown in Table V. BARAZAN D Plus suspensionagent/viscosifier is a dispersion enhanced xanthum gum that iscommercially available from Halliburton Energy Services, Inc.FILTER-CHECK filtration control agent is a modified starch that iscommercially available from Halliburton Energy Services, Inc. CLAY SYNCshale stabilizer is a clay inhibitor for water-based mud commerciallyavailable from Halliburton Energy Services, Inc. CLAY GRABBER flocculantis a polymeric additive for water-based drilling fluids commerciallyavailable from Halliburton Energy Services, Inc. CLAY SEAL shalestabilizer is a chemical drilling fluid additive commercially availablefrom Halliburton Energy Services, Inc.

TABLE V Mud Formulations Fresh Water 10% (w/w) NaCl 24% (w/w) NaClSample, (lb/gal) 13 13 10 13 13(w/o 16 NaOH) Fresh Water, bbl 0.826 — —— — — 10%(w/w), NaCl, — 0.845 — — — — bbl 24%(w/w), NaCl, — — 0.9940.875 0.875 0.756 bbl NaOH, lb 0.25 0.25 0.25 0.25 — 0.25 BARAZAN D PLUS0.75 0.75 1.0 0.75 0.75 0.25 suspension agent/ viscosifier, lbFILTER-CHECK 4.0 4.0 4.0 4.0 4.0 4.0 filtration control agent, lb CLAYSYNC shale 3.25 2.75 2.0 2.0 2.0 2.0 stabilizer, lb CLAY GRABBER 0.500.5 0.5 0.5 0.5 0.5 flocculant (active), lb CLAY SEAL shale 4.0 4.0 4.04.0 4.0 4.0 stabilizer, lb Barite, lb 256.3 228.3 81.5 183.2 183.2 358.3

All the muds from Table V were hot rolled at 150° F. in an oven for 16hrs. The pH measurements were taken after the hot roll. The densities ofthe muds as mixed with the 24% (w/w) NaCl were measured as shown inTable VI. The mud from Table V (24% (w/w) NaCl (density=13) was added adifferent amount of NaOH to adjust the pH of the muds and to determinehow much mud was needed to achieve the same results.

TABLE VI How Density and pH Affect the Performance of AE 200 Polymer 24%(w/w) NaCl Density, 10 13 13 13 16 (lb/gal) Mud vol. 10 10 10 10 10 (mL)pH 9.05 7.66 9.06 11.0 9.05 AE 200 4 3 3 3 2 polymer (mL) ObservationsIt needs the It takes the It takes the There is no It takes only 2 mLmost AE 200 longest time same amount significant of AE 200 polymer toform (1.5 min. vs. of AE 200 difference polymer to polymer paste/ ~1min.) to polymer to when pH form solids. The harden form changes frompaste/solids. texture of the compared with solids/paste 9 to 11. Thepaste is also the all other mud when the texture/strength most loose onewith the same density is the of the solid among all other density, butsame formed also is samples. different pH. regardless of the best. thedifferences in pH.

Density may play an important role on the quality of the solid aftermixing mud with AE 200 polymer and may also determine the amount of AE200 polymer needed to form the solid. As shown in Table VI, under thesame conditions, the lower the density, the more AE 200 polymer may beused to form the solid (4 mL of AE 200 polymer for D=10 vs. 2 mL AE 200polymer for D=16, that is 50% decrease in volume.).

It was observed that the solid forms using the mud with density of 16was noticeably thicker and stronger than the mud with a density of 10.Under the same conditions, by comparing the mud with pH=7.66 and 11, itwas observed that it takes 1.5 min. to form the solid at pH=7.66 vs. 1min. for pH=11, which may be attributed to “salt poisoning” (e.g.,cation poisoning effect) on AE 200 polymer. The lower the pH, the morefree H⁺ ions that may be in the solution, and the worse the saltpoisoning effect AE 200 polymer may have. However, there was no observeddifference when the pH was changed from 9 to 11.

Example 5

Salinity of the muds from EXAMPLE 4 were tested. It was observed thatsalinity had a greater effect on the performance of AE 200 polymer thanpH. Table VII shows the salinity results.

TABLE VII How Salinity Affects the Performance of AE 200 PolymerFreshwater 10% (w/w) NaCl 24% (w/w) NaCl Density, 13 13 13 (lb/gal) Mudvol. 10 10 10 (mL) pH 9.03 9.05 9.06 AE 200 1 2 3 polymer (mL)Observations It needs only 1 mL AE 200 The texture and strength AE 200polymer still works polymer to form polymer of the solid is between in24% NaCl (w/w) mud. It paste/solid. The texture of freshwater and 24%just needs more AE 200 the paste is also the best (w/w) NaCl. polymer toform solid/paste. among all other samples.

The freshwater mud from Table VII performed the best in terms of theamount of AE 200 polymer used, and the quality of the solid forms aftermixing. Again, with more cations in the solution, more AE 200 polymerwas needed to form the solid. Therefore, the increasing amount of AE 200polymer used when the salinity increases can be seen in Table VII. Inorder to find out if the presence of KCl would affect the performance ofAE 200 polymer, two experiments were done with the results shown inTable VIII.

TABLE VIII Sample 10% KCl 3% KCl + 24% NaCl AE 200 polymer (3 mL):SaltForms solid Forms solid Solution (10 mL)

The results show that there are no problems forming solid whether it isin 10% KCl solution or 24% NaCl with 3% KCl solution, as long as thereis enough AE 200 polymer in the mixture (in this case, 3 mL AE 200polymer).

Example 6

AD 200 polymer was tested with various muds, and the results are shownin Table IX. AD 200 polymer is the dehydrated form of AE 200 polymer.The test method here is similar to the test noted above. 1 mL of AD 200polymer and 20 mL of mud were mixed in a beaker. The time it took forthe mixture to harden was recorded. The texture of the solid pastes werecompared.

TABLE IX AD 200 polymer with Various Water Based Muds Sample 1:20 (v/v)(AD 200 polymer: Mud) HYDRO-GUARD Thicken and form polymer solid within1 min. system Lignosulfonate Mud Thicken and form polymer solid within 1min. Lignosulfonate Mud Thicken and form polymer solid within 1 min.with 6 ppb Lime Lignosulfonate Mud Thicken and form polymer solid within1 min. with 6 ppb Lime However, the time required to form a polymer (0.5g of Na₂CO₃ was solid for this mud is shorter than the one from addedbefore adding above. The strength and texture of the polymer AD 200polymer) solid are also better than the one obtained from above. GEM GPMud Thicken and form polymer solid within 1 min.

HYDRO-GUARD system is a mud that is commercially available fromHalliburton Energy Services, Inc. and is a water-based mud. GEM GP(general purpose) is a glycol enhanced mud that is commerciallyavailable from Halliburton Energy Services, Inc. and is also awater-based mud. It was observed that AD 200 polymer worked very wellwith different water-based muds. In addition, it was observed that therewas no problem forming a solid even with high lime mud. The result iseven better when soda ash was added to the high lime mud before addingAD 200 polymer.

Example 7

In order to find a safe way to deliver AD 200 polymer down hole, anappropriated spacer for the job was used. Table X summarized the resultsof such finding. AD 200 polymer in a mud was tested with an emulsifier(e.g., LE SUPERMUL emulsifier), which was used as the spacer. Theresults of the tests are shown in Table X.

TABLE X Wetting Agent, Spacer, Mud, AD 200 polymer and theirCompatibility and Stability Sample Comments LE SUPERMUL emulsifierWetting agent (polyaminated fatty acid) SF Base oil Main component ofthe spacer 2%(v/v) LE SUPERMUL emulsifier in Spacers will be used inwater mud systems. It SF Base oil should be used before and afterdelivering AD 200 polymer down hole. Spacer:AD 200 polymer (10 mL:10 mL)No problems on stability or compatibility. It takes 25 mL of water toinvert the emulsion. Lignosulfonate Mud:Spacer:AD 200 No problem formingpolymer solids. polymer (1:1:0.5) GEM GP Mud:Spacer:AD 200 polymer Noproblem forming polymer solids. (1:1:0.5)

SF Base oil is an internal olefin available from Halliburton EnergyServices, Inc. It was observed that no problem occurred when AD 200polymer was weighted up to 19 lb/gal with barite.

Example 8

AD 200 polymer was tested with ACCOLADE drilling fluid. ACCOLADE fluidis a clay-free synthetic based drilling fluid that is commerciallyavailable from Halliburton Energy Services, Inc. The formulation of themud is listed in Table XI. Table XII shows results of different mixes ofAD 200 polymer with the ACCOLADE fluid. The ACCOLADE fluid wasformulated as in Table XI and then hot rolled at 150° F. in an oven for16 hours. ADAPTA filtration reducer is a copolymer that provides HPHTfiltration control in non-aqueous fluid systems that is commerciallyavailable from Halliburton Energy Services, Inc. BARACARB bridging agentis carbonate particles commercially available from Halliburton EnergyServices, Inc. RHEMOD L viscosifier is commercially available fromHalliburton Energy Services, Inc.

TABLE XI ACCOLADE Mud Formulation. Sample, (lb/gal) (12.0 lb/gal) 70/30Oil:Water Water phase salinity 250,000 ppm ACCOLADE fluid base, 0.436bbl LE SUPERMUL 10 emulsifier, lb/bbl Water, bbl 0.24 Lime, lb/bbl 1ADAPTA HP filtration 2 reducer, lb/bbl Barite, lb/bbl 188.96 REV-DUSTadditive, 20.0 lb/bbl BARACARB 25 agent, 7.5 lb/bbl BARACARB 50 agent,7.5 lb/bbl CaCl₂, lb/bbl 29.09 RHEMOD L suspension 1 agent/viscosifier,lb/bbl

TABLE XII Preliminary Lab Test Results of AD 200 polymer with ACCOLADEMud 1.0 g Na₂CO₃ in Sample 0.1 g of Na₂CO₃ in Different Amount of Water(mL) Water (mL) AD 200 5 10 15 20 10 polymer:Mud (2 mL:1 mL)Observations Solid forms Solid forms Solid forms Solid forms No solidform for at in less than in less than in less than in 1 min. least 3hrs. After 1 min. 1 min. 1 min. overnight, a paste forms, but it is notas thick as using 0.1 g of Na₂CO₃ in 10 mL water.

It was observed that 1 mL of AD 200 polymer mixed with 20 mL of mud andwas able to form a solid/paste mixture. It was also observed that a 2:1(AD 200 polymer:mud) mixing ratio, plus 20 mL of soda ash solution wasused to form the solid/paste as shown in Table XII. When 2 mL of AD 200polymer was mixed with 1 mL of mud, the concentration of AD 200 polymerchanged from 50% to 33.33% (e.g., 33% active AD 200 polymer reacted with20 mL of soda ash solution to form a solid). The amount of Na₂CO₃ used(0.1 g) was calculated based on the stoichiometric amount of Ca²⁺ in thesolution. 1.0 g of Na₂CO₃ was used instead of 0.1 g to observe whetherexcess Na₂CO₃ affected the performance of AD 200 polymer. Excess Na₂CO₃functioned as salt poisoning for AD 200 polymer, therefore the mixturehad a harder time forming the solid.

It was observed that the texture of the solids from the oil mud was notas good as the water-based mud. Therefore, additional solid was added asshown in Table XIII. STEEL SEAL is a graphite that is commerciallyavailable form Halliburton Energy Services, Inc.

TABLE XIII Preliminary Lab Test Results of AD 200 polymer with ACCOLADEMud Sample 0.1 g of Na₂CO₃ in 10 mL Water AD 200 3.0 g Barite 3.0 gREV-DUST 3.0 g STEEL polymer:Mud additive SEAL lost (2 mL:1 mL)circulation additive Observations Solid forms in less than 1 min forSolid forms in both cases. REV-DUST additive less than 1 min. may beslightly better although no The texture of the differences were observedon the solid is the texture of the solid between barite best of thethree. and REV-DUST additive.

It was observed that the added solid provided a better final paste bothon the texture and the strength.

Example 9

Two more oil-based muds were tested with AD 200 polymer (PETROFREE SFfluid and ENVIROMUL fluid). PETROFREE drilling fluid is commerciallyavailable from Halliburton Energy Services, Inc. ENVIROMUL drillingfluid is commercially available from Halliburton Energy Services, Inc.Their formulations are shown in Tables XIV and XV. GELTONE IIviscosifier and GELTONE V viscosifier are gelling and viscosifyingagents comprising ground organophillic clay, which are available fromHalliburton Energy Services, Inc. Both muds were hot rolled in a 150° F.oven for 16 hrs. ESCAID fluid is an oil that is commercially availablefrom Exxon Chemical Company. SUSPENTONE suspension agent is anorganophilic clay commercially available from Halliburton EnergyServices, Inc. EZ MUL NT emulsifier is a synthetic-based mud emulsifiercommercially available from Halliburton Energy Services, Inc. DURATONEHT (high temperature) oil mud filtration control agent comprises anorganophillic lignite blend and is commercially available fromHalliburton Energy Services, Inc. DEEP-TREAT thinner is a wetting agentcommercially available from Halliburton Energy Services, Inc., andCOLDTROL thinner is commercially available from Halliburton EnergyServices, Inc. The tests involved adding 20 mL water to a beaker,followed by Na₂CO₃. STEELSEAL additive, barite or REV-DUST additive werealso added if needed. 2 mL of AD 200 polymer and 1 mL of mud were thenadded to the beaker. The contents of the beaker were then mixed. Thetime needed for the mixture to harden was recorded. The results of thetests are shown in Table XVI.

TABLE XIV PETROFREE SF Mud Formulation. Sample, (lb/gal) (12.0 lb/gal)70/30 Oil:Water Water phase salinity 250,000 ppm SF Base (IO), bbl 0.426LE SUPERMUL 8 emulsifier, lb/bbl ADAPTA HP filtration 1 reducer, lb/bblWater, bbl 0.257 RHEMOD L suspension 0.25 agent/viscosifier Barite,lb/bbl 208.1 CaCl₂, lb/bbl 29.11 REV-DUST additive, 10.0 lb/bbl BARACARB5 agent, 10.0 lb/bbl GELTONE II viscosifier, 4.0 lb/bbl

TABLE XV ENVIROMUL Mud Formulation. Sample, (lb/gal) (12.0 lb/gal) 70/30Oil:Water Water phase salinity 250,000 ppm ESCAID fluid 110, 0.524 bblWater, bbl 0.233 GELTONE V 12.0 viscosifier, lb/bbl SUSPENTONE 4.0agent, lb/bbl EZ MUL NT 5.0 emulsifier, lb/bbl INVERMUL NT 4.0emulsifier, lb/bbl Lime, lb/bbl 2 DURATONE HT 8.0 filtration controlagent DEEP-TREAT 5.0 thinner, lb/bbl COLDTROL thinner, 2.5 lb/bbl CaCl₂,lb/bbl 28.4 Barite, lb/bbl 209.8

TABLE XVI Test Results of AD 200 polymer with PETROFREE SF and ENVIROMULMud 0.1 g Na₂CO₃ 0.1 g Na₂CO₃ and 3 g and 3 g 0.1 g 1.0 g STEELSEAL 0.1g Na₂CO₃ REV-DUST Sample Na₂CO₃* Na₂CO₃ material and 3 g barite additiveAD 200 Solid Solid Solid forms in 1.5 min. The texture and thepolymer:PETROFREE forms forms in strength of the paste are better thanwithout mud SF (2:1) in 1.5 min 15 min adding any solid. The ones withSTEELSEAL material and REV-DUST additive look better than barite. AD 200Solid Solid Solid forms in 1 min. The texture and the polymer:ENVIROMULforms forms in strength of the paste are better than without mud (2:1)in 5 min adding any solid. The one with STEELSEAL 1 min material looksthe best. *All experiments in this table are done with 20 mL of water.

From EXAMPLES 8 and 9, it can be seen that the tests results of AD 200polymer with PETROFREE SF and ENVIROMUL muds are similar to ACCOLADEmud.

While preferred embodiments of the invention have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit and teachings of the invention. Theembodiments described herein are exemplary only, and are not intended tobe limiting. Many variations and modifications of the inventiondisclosed herein are possible and are within the scope of the invention.Where numerical ranges or limitations are expressly stated, such expressranges or limitations should be understood to include iterative rangesor limitations of like magnitude falling within the expressly statedranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4,etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). Use of theterm “optionally” with respect to any element of a claim is intended tomean that the subject element is required, or alternatively, is notrequired. Both alternatives are intended to be within the scope of theclaim. Use of broader terms such as comprises, includes, having, etc.should be understood to provide support for narrower terms such asconsisting of, consisting essentially of, comprised substantially of,etc.

Accordingly, the scope of protection is not limited by the descriptionset out above but is only limited by the claims which follow, that scopeincluding all equivalents of the subject matter of the claims. Each andevery claim is incorporated into the specification as an embodiment ofthe present invention. Thus, the claims are a further description andare an addition to the preferred embodiments of the present invention.The discussion of a reference in the Background of the Invention is notan admission that it is prior art to the present invention, especiallyany reference that may have a publication date after the priority dateof this application. The disclosures of all patents, patentapplications, and publications cited herein are hereby incorporated byreference, to the extent that they provide exemplary, procedural orother details supplementary to those set forth herein.

1. A sealant composition comprising an inverse emulsion polymer, whereinthe inverse emulsion polymer comprises particles having a particle sizefrom about 0.01 microns to about 30 microns, and wherein the inverseemulsion polymer is dehydrated prior to formation of the sealantcomposition to comprise from about 0 wt. % to about 10 wt. % water. 2.The sealant composition of claim 1, wherein the inverse emulsion polymercomprises a water swellable polymer.
 3. The sealant composition of claim2, wherein the water swellable polymer comprises a synthetic polymer, asuperabsorber, a natural polymer, or combinations thereof.
 4. Thesealant composition of claim 2, wherein the inverse emulsion polymercomprises from about 5 wt. % to about 100 wt. % water swellable polymerby total weight of the inverse emulsion polymer.
 5. The sealantcomposition of claim 1, wherein the inverse emulsion polymer comprisesfrom about 10 wt. % to about 80 wt. % by oil by total weight of theinverse emulsion polymer.
 6. The sealant composition of claim 1, whereinthe inverse emulsion polymer comprises a petroleum oil, a natural oil, asynthetically derived oil, a mineral oil, a silicone oil, orcombinations thereof.
 7. The sealant composition of claim 1, wherein thesealant composition has a density of from about 10 ppg to about 20 ppg.8. The sealant composition of claim 1, wherein the inverse emulsionpolymer has a pH of from about 5.1 to about 8.0.
 9. The sealantcomposition of claim 1, wherein the inverse emulsion polymer has adensity of from about 1.0 g/ml to about 2.5 g/ml.
 10. The sealantcomposition of claim 1, wherein the sealant composition is effective toreduce a loss of fluid to the subterranean formation during placement ofthe fluid in a wellbore in which the sealant composition has beenplaced.
 11. The sealant composition of claim 10, wherein the fluidcomprises a water-based drilling fluid or a nonaqueous drilling fluid.12. The sealant composition of claim 10, wherein the fluid comprises atreating fluid.
 13. A sealant composition comprising an inverse emulsionpolymer, wherein the inverse emulsion polymer comprises from about 10wt. % to about 80 wt. % oil by total weight of the inverse emulsionpolymer, wherein the inverse emulsion polymer comprises from about 0 wt.% to about 70 wt. % water by total weight of the inverse emulsionpolymer, wherein the inverse emulsion polymer has a pH of from about 5.1to about 8, and wherein the inverse emulsion polymer is dehydrated priorformation of the sealant composition to comprise from about 0 wt. % toabout 10 wt. % water.
 14. The sealant composition of claim 13, whereinthe inverse emulsion polymer comprises a water swellable polymercomprising a synthetic polymer, a superabsorber, a natural polymer, orcombinations thereof.
 15. The sealant composition of claim 13, whereinthe sealant composition has a density of from about 10 ppg to about 20ppg.
 16. A sealant composition comprising an oil dispersed polymercomprising particles having a particle size from about 0.01 microns toabout 30 microns, and wherein the oil dispersed polymer is dehydratedprior to formation of the sealant composition to comprise from about 0wt. % to about 10 wt. % water.
 17. The sealant composition of claim 16,wherein the oil dispersed polymer comprises a petroleum oil, a naturaloil, a synthetically derived oil, a mineral oil, a silicone oil, orcombinations thereof.
 18. The sealant composition of claim 16, whereinthe oil dispersed polymer comprises from about 0 wt. % to about 10 wt. %water.
 19. The sealant composition of claim 16, wherein the oildispersed polymer comprises a water swellable polymer.
 20. The sealantcomposition of claim 16, wherein the water swellable polymer comprises asynthetic polymer, a superabsorber, a natural polymer, or combinationsthereof.